SPP PMU Communications Handbook pmu communication... · 2019-02-08 · SPP PMU Communication...

S PP P MU Communi c at i o ns Handbook

SPP PMU Project Team

Southwest Power Pool, Inc.

SPP PMU Communication Handbook 1

Revision History

Date or Version Number

Author Change Description Comments

11/09/16 Lance Reaves Initial Creation of Approach for Review.

First Draft

12/1/16

Lance Reaves First revision. Adding to draft.

5/23/17 Lance Reaves Second revision. Adding to draft.

6/22/17 Lance Reaves Third revision. Data quality section changes.

6/28/17 Mike Nugent Fourth revision. Updated naming conventions.

9/27/17 Lance Reaves Fifth revision Added recommended SIEGate/PDC listening port numbers.

10/25/17 Lance Reaves/Mike Nugent

Sixth revision Changes discussed on 10/2 SST conference call.

12/1/17 Lance Reaves/Mike Nugent

Seventh revision Ready to be reviewed for approval by SST

12/12/17 Mike Nugent Seventh revision discussed in 12/11/17 SST meeting

Edits reviewed with SST and accepted. Minor edits to bandwidth table

1/5/2018 Lance Reaves Version 1.0 SST approved Version 1.0.



1 Table of Contents Revision History 1

2 Introduction 4

2.1 Intended Audience 4

2.2 References 4

2.3 Glossary 5

3 SPP Synchrophasor System Architecture 6

4 SPP Synchrophasor Standards, Policies, and Conventions 7

4.1 C37.118 Naming Conventions 7

4.1.1 16-Character PMU Name 7 4.1.2 16-Character Signal Name 8 4.1.3 Naming Examples 9

4.2 Gateway Exchange Protocol (GEP) Naming Conventions 10

5 Synchrophasor Communication System 10

5.1 Phasor Measurement Unit Device Requirements 11

5.2 Phasor Data Concentrator (PDC) Requirements 12

5.3 Network Requirements 12

5.4 Technical Specifications 13

6 Connecting to SPP – SIEGATE/PDC 14

6.1 Internet 14

6.2 SPPNet 15

6.3 EINet 15

7 Connecting to SPPNet 15

7.1 SPPNet Network Topology Overview 15

7.2 Remote Entity Site Connections 16

7.3 Getting Connected to SPPNet 16

8 Synchrophasor Data Exchange Requirements 17

8.1 Synchrophasor Data Exchange Standards 17

8.2 Synchrophasor Data Format 17

8.3 Synchrophasor Communication Parameters Definition Error! Bookmark not defined. 9 Synchrophasor Network Data Quality 18

9.1 Data Correctness 18

9.2 Data Completeness 20

10 Appendix 23

10.1.1 SPP EMS Model Area Names 23



2 Introduction

The SPP PMU Communications Handbook sets practices, conventions, and fundamental parameters required for PMU data to be exchanged with SPP. Also included in the Handbook is a description of the physical network infrastructure required. Specifics regarding the use of this data are beyond the scope of this document.

The Handbook specifies important configuration and functional requirements for PMU implementations so that the user’s system will interoperate with SPP’s system. Users, and if applicable, their vendors, will need this information to include the required features and to build the properly delivered PMU configuration. SPP has the following planned uses of PMU data:

• Diagnosing Mis-Operations • Model Validation • Oscillation Detection and Monitoring • Phase Angle Monitoring • Post Event Analysis • Voltage Stability Monitoring • Wide Area Situational Awareness

2.1 Intended Audience This handbook is for the reader seeking to quickly acquaint themselves with PMU data connections, how the network operates, and how to request information. Diagrams will be available throughout this handbook to aid in visualization and understanding. Criteria will be quoted and referenced throughout the document. Anyone using this document should have:

• General knowledge of data communications concepts • Working knowledge of PMU functions and concepts • Familiarity with modern data communications technology • Knowledge of TCP/IP protocol concepts

2.2 References Grid Protection Alliance: Open source software corporation specializing in Synchrophasor related software. Makers of SIEGate and openPDC software as shown in the Phase 1 deployment diagram in this document. https://www.gridprotectionalliance.org/ Electric Power Group: Commercial software corporation specializing in Synchrophasor related software. Makers of ePDC, RTDMS, ISG, and PDGA software as shown in the Phase 1 deployment diagram in this document. http://www.electricpowergroup.com/ North American Synchrophasor Initiative: https://www.naspi.org/

https://www.gridprotectionalliance.org/

http://www.electricpowergroup.com/

https://www.naspi.org/



NASPI PMU Data Quality White Paper, March 2017 v1.0 https://www.naspi.org/sites/default/files/reference_documents/PARTF_WhitePaper_20170314_Final_PNNL_26313.pdf?fileID=1689 NERC Reliability Guideline – PMU Placement and Installation http://www.nerc.com/pa/RAPA/rg/ReliabilityGuidelines/Reliability%20Guideline%20-%20PMU%20Placement.pdf PEAK PRSP Phasor Gateway Evaluation Report https://www.naspi.org/sites/default/files/2017-03/PRSP_Phasor_Gateway_Whitepaper_Final_with_disclaimer_Final.pdf

2.3 Glossary Synchrophasor: Synchrophasors are time-synchronized numbers that represent both the magnitude and phase angle of the sine waves found in electricity, and are time-synchronized for accuracy. They are measured by high-speed monitors called Phasor Measurement Units (PMUs) that are 100 times faster than SCADA. PMU measurements record grid conditions with great accuracy and offer insight into grid stability or stress. PMU (Phasor Measurement Unit): Phasor Measurement Units (PMUs) are substation devices that directly measure amplitude and phase angle of current and voltage quantities at a high sampling rate (typically 30-60 samples per second.) PMU devices have high-precision time synchronization (via GPS) which supports direct comparison of measured values (synchrophasors) from different points on the grid. PMU devices also derive Frequency and Rate of Change of Frequency (ROCOF) from the measured voltage phase angle. PDC (Phasor Data Concentrator): are devices which aggregate and time synchronize (or time align) phasor data streamed from Phasor Measurement Units (PMUs) and output the data for applications and archival. Grid Protection Alliance SIEGate: an application designed to securely exchange data among devices (such as other SIEGate nodes) using GPA's Gateway Exchange Protocol. SPPNet: Southwest Power Pool's private WAN used for secure, redundant communications between SPP and Market Participants. TCP (Transmission Control Protocol): a protocol used along with the Internet Protocol (IP) to provide reliable, ordered, and error-checked delivery of a stream of octets between applications running on hosts communicating by an IP network. VPN (Virtual Private Network): A VPN extends a private network across a public network, such as the Internet. It enables a computer to send and receive data across shared or public networks as if it is directly connected to the private network, while benefiting from the functionality, security and management policies of the private network. A VPN is created by establishing a virtual point-to-point connection through the use of dedicated connections, virtual tunneling protocols, or traffic encryptions.

https://www.naspi.org/sites/default/files/reference_documents/PARTF_WhitePaper_20170314_Final_PNNL_26313.pdf?fileID=1689

https://www.naspi.org/sites/default/files/reference_documents/PARTF_WhitePaper_20170314_Final_PNNL_26313.pdf?fileID=1689

http://www.nerc.com/pa/RAPA/rg/ReliabilityGuidelines/Reliability%20Guideline%20-%20PMU%20Placement.pdf

http://www.nerc.com/pa/RAPA/rg/ReliabilityGuidelines/Reliability%20Guideline%20-%20PMU%20Placement.pdf

https://en.wikipedia.org/wiki/Reliability_(computer_networking)

https://en.wikipedia.org/wiki/Error_detection_and_correction

https://en.wikipedia.org/wiki/Octet_(computing)



WAN (Wide Area Network): A network of computers interconnected over large distances for sharing resources or exchanging data.

3 SPP Synchrophasor System Architecture

SPP’s Phase 1 Deployment Model is planned as shown below. This is a single site architecture residing in SPP’s non-ESP Production environment. Communication with Members and other external entities’ SIEGate/PDCs will only be supported via Internet connections. This can be done either using Gateway Exchange Protocol via a SIEGate connection, or C37.118 via a PDC connection within a VPN tunnel.



4 SPP Synchrophasor Standards, Policies, and Conventions

4.1 C37.118 Naming Conventions The C37.118 data protocol used to send and receive synchrophasor has specific built-in fields for identifying measurements. This naming and identification data will typically be configured in each PMU and automatically passed upstream to all PDCs and data clients. In situations where the PMU does not support changing signal or device names, those names should be configured in the PDC before sending on to SPP or other downstream consumers. There are two configuration parameters, STN or Station Name and CHNAM or Channel Name. The Station Name is the name of substation and PMU identifier. There will generally be several signals, or CHNAM channels, under each STN. All STN and CHNAM are 16 characters or bytes long. SPP has chosen to adopt common naming conventions based on those in use by PJM, MISO, PEAK, and others in the industry. This convention aims to identify the company, substation, measurement location, voltage level, device type, and equipment name using the 16-character STN/PMU and CHNAM/Signal names, and provides a relationship to the EMS model. 4.1.1 16-Character PMU Name

1. Company Identifier (4 characters) - Company identifier based on the TO’s Area name in SPP’s EMS model (see Appendix 10.1.1). Pad to the right with underscores if less than 4 characters.

2. Generator Indication (2 characters) – a. If PMU is associated with a generator (i.e. directly measures a generator, generator

step-up transformer, radial line to a generator, etc.) enter ‘UN’ b. Otherwise fill with underscores ‘__’

3. Substation Name (8 characters) – SPP EMS Model Substation name. SPP staff can assist

with determining the correct name, if necessary. Pad to the right with underscores if less than 8 characters.



4. PMU ID (2 digit integer from 01-99) – Order of PMU in the substation (e.g. ‘01’, ‘02’, ‘03’ if multiple PMUs are installed). Should correspond with measured equipment identifier, if possible. For example, if a substation has generators 1-3 each with its own PMU device, the PMU device ID’s should be named ‘01’-‘03’. If only one PMU is installed, use ‘01’.

Example: SPS___STATION101 For readability and compatibility, it is best practice to avoid using embedded spaces in signal or device names. 4.1.2 16-Character Signal Name

1. Measurement (1 character) - to identify measurement location or equipment type i. B - Bus Side Phasor

ii. L – Line Side Phasor iii. T – Transformer Phasor iv. G – Generator Phasor v. C – Capacitor Phasor

vi. R – Reactor Phasor vii. S – Static Var Compensator Phasor

viii. A – Analog (non-phasor use for frequency, df/dt, Watts, VARs, or any single value scalar)

ix. D – Digital or status i.e. 1 or 0

2. Nominal Volts (3 digit integer from 001-999) - nominal voltage in kV (e.g. ‘345’). For voltages such as 13.8 round to the nearest whole number. For 2 digit voltages, prefix with a 0, e.g. ‘069’.

3. “To Bus” Name (9 characters) i. For a line, the SPP EMS Name of the substation on the opposite end of the line. SPP

staff can assist with determining the correct name, if necessary. ii. For a bus section, the identifier of the bus being measured (e.g. ‘NORTH’, ’SOUTH’,

’1’, etc.) iii. For transformers, generators, and reactive devices, a descriptive name of the

equipment (e.g. ‘345/138’, ‘UN2_GSU’, ‘UNIT1’, ‘BANK1’, etc.)



4. Circuit ID (1 character) – If parallel lines or transformers exist, enter the applicable circuit ID of the equipment (e.g. ‘A’,’B’,’1’,’2’,’N’,’S’). Otherwise, enter ‘1’.

5. Measurement Identifier (2 characters) – applicable signal identifier as noted in the table

below:

Signal Identifier

Measurement Quantity Measurement Type

V1 Voltage Positive Sequence I1 Current Positive Sequence V0 Voltage Zero Sequence I0 Current Zero Sequence V2 Voltage Negative Sequence I2 Current Negative Sequence FQ Frequency Frequency DF df/dt Frequency rate of change VA Voltage Phase A VB Voltage Phase B VC Voltage Phase C IA Current Phase A IB Current Phase B IC Current Phase C

4.1.3 Naming Examples The following examples use made-up Area, Substation, and Equipment names to demonstrate the PMU and Signal naming convention for C37.118 protocol data streams.

1. TO with an EMS Area name “EX” has 2 PMUs located at station “STATN1”, each measuring a parallel 230kV line going to “STATN2”.

a. Line PMU1: EX____STATN1__01 i. Freq: L230STATN2___1FQ

ii. Pos. Sequence Voltage: L230STATN2___1V1 iii. Pos Sequence Current: L230STATN2___1I1 iv. Df/dt: L230STATN2___1DF

b. Line PMU2: EX____STATN1__02

i. Freq: L230STATN2___2FQ ii. Pos. Sequence Voltage: L230STATN2___2V1

iii. Pos Sequence Current: L230STATN2___2I1 iv. Df/dt: L230STATN2___2DF

2. TO with an EMS Area name “POWR” has 2 PMUs located at station “PW_PLANT”. One

PMU directly measures a 13.8kV Generator named “Unit 1”. The other PMU measures a Generator Step Up transformer on the high side at 345kV, as well as a 345kV line to SWTCHST.



a. Generator PMU: POWRUNPW_PLANT01 i. Freq: G014UNIT1____1FQ

ii. Pos. Sequence Voltage: G014UNIT1____1V1 iii. Pos Sequence Current: G014UNIT1____1I1 iv. Df/dt: G014UNIT1____1DF

b. Line/XFMR PMU: POWRUNPW_PLANT02

i. Freq: L345SWTCHST__1FQ ii. Pos. Seq. V for 345 bus: L345SWTCHST__1V1

iii. Pos. Seq. I for 345 line: L345SWTCHST__1I1 iv. Pos. Seq. I for XFMR: T345UNIT1_GSU1I1 v. Df/dt: L345SWTCHST__1DF

c. In this case, the second PMU device has 1 voltage phasor and 1 current phasor

measured from the line, and an additional current phasor measured from the transformer. The PMU device is still marked with “UN” because it has measurements directly related to a generator (the generator step-up transformer).

4.2 Gateway Exchange Protocol (GEP) Additional Fields The Gateway Exchange Protocol offers additional metadata fields that can be configured if data is being sent using GEP. Typically, these fields would be configured in the user’s openPDC, and would be automatically propagated downstream to SIEGate and SPP.

• Device Level Metadata Fields o Acronym – Same as 16-Character PMU Name in section 4.1.1 o Name – Option for Friendly Name/Common Name, or same as Acronym o Company – The Company that owns the device o Interconnection (Eastern or Western) o Device Vendor (optional) – Model of PMU device o Longitude/Latitude – GIS coordinates of the device o Frames per Second

• Phasor Metadata Fields o Label – Same as 16-Character Signal Name in section 4.1.2 o Type – Voltage or Current o Phase – A,B,C, + Sequence

5 Synchrophasor Communication System

The SPP Synchrophasor Communication System allows SPP to collect and manage data from both standalone phasor measurement units (PMUs) as well as Relays and Digital Fault Recorders (DFRs). Below are examples of minimum PMU architectures that support streaming PMU data to SPP’s control center, starting from the substation and ending at SPP.



5.1 Phasor Measurement Unit Device Requirements A phasor measurement device (PMU) is a device which measures electrical quantities from the grid in real-time, using a common time-source for synchronization. Please refer to the section titled PMU Installations in the SPP Members PMU Planning Approach document for more information.

• The performance of the PMU must comply at minimum with the 2005 revision of the IEEE

C37.118 standard. The protection (P) performance class PMU is preferred. Synchrophasor data acquisitions are defined in the following main IEEE standards and guides:

o C37.118.1-2011 – Measurement requirements. Synchrophasor measurements including frequency and rate of change of frequency

o C37.118.2-2011 – Synchrophasor communications Extension of the original synchrophasor standard (2005)

o IEEE 1588 – Standard for a Precision Clock Synchronization Protocol for Networked Measurement and Control Systems

• The PMU shall have the capability to calculate positive-sequence values for voltage and current Phasor data; as well as to provide the positive-sequence synchrophasor values to a



PDC at the minimum rate of 30 samples per second. (For all calculation purposes Phase A shall be used as the reference phase.)

• The PMU shall have GPS (UTC) synchronization function either through an internal or external GPS receiver. All data recorded shall be in the Coordinated Universal Time (UTC)

• Accuracy and resolution of time synchronization shall be less than or equal to 5 micro seconds to UTC (recommended in NERC Reliability Guideline on PMU Placement).

5.2 Phasor Data Concentrator (PDC) Requirements The PDC at the Transmission Owner (TO) control center is the central point of collection, management, and distribution of PMU data for authorized real-time and non-real time uses.

• The performance of the TO PDC should comply with the current revisions of standards such as IEEE C37.118.

• The TO PDC shall be able to consolidate and synchronize data from all connected PMUs before sending it to SPP.

• The TO PDC shall have capability of assigning positive sequence reference to any phase

(rotate it by 120 or 240 degrees on per signal basis).

• All data streaming from the TO PDC to SPP PDC shall be in compliance with IEEE C37.118 communication standards or SIEGate gateway exchange protocol or equivalent.

• The TO PDC should have the capability to down-sample PMU signals to a rate of 30 samples per second before transmitting to the SPP PDC. This is only needed if the source sampling rate is greater than 30 samples per second.

• The TO PDC should have a clock that is synchronized to UTC. It is recommended that this clock be an external GPS clock. Resolution and accuracy of time synchronization at the PDC should be equal or under 1 micro second to UTC.

5.3 Network Requirements The following table summarizes the data transmission bandwidth requirements using the C37.118 and Gateway Exchange (GEP) protocols, assuming a TCP/IP network. Three typical situations are presented:

• PMU transmitting 2 phasors (positive-sequence V and I), Frequency and dF/dT analogs and status digital

• PMU transmitting 8 phasors (three-phase and positive-sequence V and I), Frequency and dF/dT analogs and status digital

• DDR transmitting 32 phasors (three-phase and positive sequence V and I for four separate measured terminals), Frequency and dF/dT analogs and a status digital for each terminal



Bandwidth Needed (in kbps) for Data Transmission of Floating-Point Synchrophasor Data Using the C37.118 (un-encrypted) and Gateway Exchange Protocols over TCP/IP

Protocol c37.118 GEP c37.118 GEP c37.118 GEP

# Of PMU @ Data Rate

(Frames/Sec)

2 Phasors, 2 Analog, 1 Digital

(PMU Pos. Seq. Data)


(PMU Pos. Seq. Data)

8 Phasors, 2 Analog, 1 Digital (PMU 3-

Phase + Pos. Seq. Data )

8 Phasors, 2 Analog, 1 Digital (PMU 3-

Phase + Pos. Seq. Data)


(DDR 3-Phase + Pos. Seq. x 4 Devices)


(DDR 3-Phase + Pos. Seq. x 4 Devices)

1 PMU @ 30 32.8 21.3 44.1 28.7 90.5 58.8 5 PMU @ 30 66.6 43.3 122.8 79.8 396.1 257.5

10 PMU @ 30 108.8 70.7 241.9 157.2 788.4 512.5 50 PMU @ 30 508.1 330.3 1153.1 749.5 3865.3 2512.4 1 PMU @ 60 65.6 42.6 88.1 57.3 180.9 117.6 5 PMU @ 60 133.1 86.5 245.6 159.6 792.2 514.9

10 PMU @ 60 217.5 141.4 483.8 314.5 1576.9 1025 50 PMU @ 60 1016.3 660.6 2306.3 1499.1 7730.6 5024.9 Table values for C37.118 calculated using: http://www.gridprotectionalliance.org/docs/products/gsf/GEP-bandwidth-estimator.zip. GEP values are calculated as 65% of the C37.118 bandwidth requirement, based on extensive testing of both protocols detailed in the “PRSP Phasor Gateway Evaluation Report.” The C37.118 calculator also includes estimates for transmitting data over serial. Data encryption will increase bandwidth requirements, potentially by a factor of 50-150% (assuming a PDC to PDC data transfer over a VPN connection).

5.4 Technical Specifications ***Standards below taken from the PJM Technical Guidelines for Installation of Synchrophasor Measurements at Generation Facilities. The technical requirements and guidelines below are for reference to aid new generation facilities in early planning to design and install synchrophasor measurement system that is compliant and interoperable with SPP. These requirements and guidelines can be used for initial plans, which should then be shared and reviewed with SPP during the Interconnection process. Measured Phases Voltage and current signals are required to be

streamed to SPP as the Positive Sequence component. Actual measurement of all 3 phases is required for the calculation of Positive Sequence. Note: The Transmission Owner may desire all 3 phases, SPP only requires Positive Sequence.

Signals Required for each measurement point: Voltage, Current, Voltage Angle, Current Angle,

http://www.gridprotectionalliance.org/docs/products/gsf/GEP-bandwidth-estimator.zip



Frequency, df/dt (rate of change of frequency) Scan Rate 30 samples per second streamed to SPP is

required. Data Protocol C37.118 communicating via TCP/IP, or SIEGate

GEP or equivalent. PMU to SPP PDC Latency (maximum) Maximum 2 seconds* * As recommended by Electric Power Group (EPG)

6 Connecting to SPP – SIEGATE/PDC

Connections to the SPP SIEGate or PDC may be made using three options: • Internet (either SIEGate to SIEGate or VPN) • SPPNet • EINet

Please note that while all three options are detailed below, for the Phase I deployment plan only Internet connections will be supported.

6.1 Internet There are two options for connecting via the internet:

• Grid Protection Alliance SIEGate – SIEGate is open source software that allows for encrypted communication. A direct connection can be made if SIEGate is used. More information on SIEGate is linked in the References section of this document. SPP IT staff will work directly with Member IT staff to form this connection.

• VPN – in the case of PDC to PDC connections, encryption can be at the network level using a VPN. SPP IT staff will work directly with Member IT staff to create the VPN tunnel and form the PDC to PDC connection.

Connections made via the internet cannot be guaranteed to be highly available. Highly available connections must be made via SPPNet or EINet as detailed in the sections below. Required information to form an internet connection are:

• Externally facing IP address for the Member SIEGate server or PDC. • Listening port number on the Member SIEGate server or PDC. In an effort to standardize

connection ports numbers, it is recommended that port 6172 be configured as the listening port on the Member SIEGate or PDC. If port 6172 is already in use, increment the port number by 1, continuing until an available port is found, preferably not to exceed port 6181.

• Firewalls configured to allow connections from SPP IP address (supplied by SPP). • Firewalls/network configured to allow server to server (IP to IP) authentication.

SPP IT Cyber Security recommendations for using TLS and certificates for secure communications across the internet:

• Minimum TLS version 1.2. • Certificates should be issued by a CA, rather than being self-signed.



• The server certificate should be X.509 version 3. • SHA-256 is the recommended signature hash algorithm. • A 2048-bit RSA public key and a strong encryption cipher. (e.g. ECDHE_RSA with P-256

and AES_256_GCM). • The use of the server DNS name in the Subject Alternative Name field.

6.2 SPPNet SPPNet is a private network used by Southwest Power Pool for secure, redundant communications between SPP and our member organizations. Details on connecting to SPPNet can be found in Section 7 of this document.

6.3 EINet EINet can be used if you are an existing EIDSN Member.

7 Connecting to SPPNet

The sections below detail the SPPNet architecture and connection information. ***For the Phase I deployment into the SPP Non-ESP Production environment, SPPNet will not be supported. Only Internet connections will be supported.

7.1 SPPNet Network Topology Overview SPPNet is a private network used by Southwest Power Pool for secure, redundant communications between SPP and our member organizations. Data can be exchanged between any member and SPP or between members. The data network is designed to provide redundant, secure, reliable data communications between SPP and our members with automated failover in case of loss of a circuit or router. SPPNet uses dual circuits provided by two carriers to each location. Each location connects to SPPNet via a Telecom Vendor A circuit and a Telecom Vendor B circuit. Two routers, owned and managed by SPP, are at each location. These routers are connected to the member’s network via a member supplied firewall. Members do not have access to the SPPNet routers at their location, and SPP does not have access to member firewall to provide for multi-tier security. Data passes through the member system to their endpoint firewall and then is routed by the SPPNet routers to the destination. The backbone routing structure of SPPNet is over a dual homed design as previously mentioned. Members may transmit different types of data to SPP and are not necessarily limited to ICCP or PMU data. The SPP staff maintains the architecture and communications from member to vendor. SPPNet circuits and routers are provided to our members as part of the basic membership agreement. Non-members such as Market Participants may also join SPPNet on a contract basis.



SPPNet Overview

7.2 Remote Entity Site Connections SPP provides two circuits through different vendors; Telecom Vendor A and Telecom Vendor B. SPP also provisions and preconfigures two routers to connect SPPNet to the remote entity’s network. This connection is accomplished via a small DMZ segment. The only devices on the DMZ are the two SPPNet routers provided and the firewall which is provided by the entity. All communication is accomplished via SPP assigned addresses. It is the responsibility of the remote entity to configure their router to listen and forward these addresses. Addresses will be provided by SPP to be configured on the remote entity’s firewall. The SPPNet routers will connect to the remote entity’s firewall appliances and provide the routing path back to SPP and all other entities as well as SPP’s vendor if necessary. The SPPNet routers are configured as a redundant pair reducing data loss. No manual intervention is required. Southwest Power Pool is responsible for all configuration of the routers and assumes the cost of maintenance and repair for the duration of the connection.

7.3 Getting Connected to SPPNet When a request for SPPNet connectivity is made, SPP will exchange site data with the requesting participant. The data exchanged includes location and demarc information as well as contact details. Once SPP receives this information, SPP will begin the order process and verification. After the approval process has been completed SPP will begin the order process. Lead time for circuit orders is typically 45 to 60 business days. During this time SPP will order the routers and configure them. Also, during the order process SPP will discuss with the requesting participant the technical details of the connectivity. The requesting participant is responsible for their firewall configuration during this time. SPP will ship the routers so that they will arrive at roughly the same time as the circuits are provisioned. It is then the responsibility of the requesting participant to rack and power the routers and connect them to their firewalls. Once the circuits are up and all hardware is connected SPP and the requesting participant will test connectivity with the SPP staff.



Testing passes from the network group after successful network connectivity testing. Applications groups are responsible for testing server to server connectivity.

8 Synchrophasor Data Exchange Requirements

Synchrophasor data is transmitted to SPP by SPP Members as well as other ISOs and RTOs to support uses listed in the Introduction section of this document. SPP considers this data CEII and to be shared under the NERC ORD.

8.1 Synchrophasor Data Exchange Standards • All data items and related quality codes should be transmitted at a rate of 30 frames per second in

compliance with IEEE C37.118 communication standards. • SPP Members are responsible for the accuracy of the data transmitted to SPP. A target of no

more than 5% overall inaccuracy or loss of data from SPP Members to SPP is preferred for instantaneous monitored values in Phase I of SPP’s project.

• Planned outages for SPP Member PDC systems should be reported to SPP by sending an email to [email protected] prior to taking the equipment out of service. This includes the PDC and associated Member PDC - SPP PDC communications equipment.

• Unplanned outages of the SPP Member PDC system should be reported by sending an email to [email protected].

SPP will be participating in the Advanced Synchrophasor Protocol (ASP) Development and Demonstration Project, DOE-FOA-0001492. This may replace the Gateway Exchange Protocol (GEP) mentioned earlier in this document. More information will be added to this section.

8.2 Synchrophasor Data Format The data format minimum requirements for transmitting data to SPP are defined in the following table. Parameter Value Data Format C37.118-2011/C37.118-2005 (PDC to PDC)

SIEGate Gateway Exchange Protocol (SIEGate to SIEGate) SPP Data Requirement Positive Sequence (3-Phase not required) Data Rate 30 Samples/Second PMU to SPP PDC Latency (maximum)

Maximum 2 seconds*

Communication Protocol TCP * As recommended by Electric Power Group (EPG)



9 Synchrophasor Network Data Quality

Applications that consume PMU data require accurate and reliable data that is delivered on time. The overall quality of the input data used by these applications will significantly impact the quality of the output of these applications. Data quality is a broad term that includes data:

• Accuracy (correctness) • Availability (completeness) • Timeliness/latency

Several areas along the path of PMU signal origination to final destination can affect the overall data quality, including:

• At the PMU itself (including GPS equipment and satellite signal used to timestamp the data) • Within the communications network from the PMU to the Member datacenter aggregation

site (latency, loss of communication, etc.) • At the Member datacenter aggregator (Members PDCs/SIEGate instance, historians, etc.) • Within the communications network from the Member datacenter to SPP (SPPNet, EINet,

Internet/VPN connections) • At the point of use by SPP applications

** Information on PMU equipment, PMU communications bandwidth and latency, etc. will be included in the document “SPP Members PMU Planning” document.

9.1 Data Correctness Data correctness refers to the accuracy and content of the PMU data. Issues may develop from:

• Dropouts/packet loss • Latency • Repeated values • Measurement bias • Bad/missing timestamps • Loss of GPS synchronization • Incorrect signal meta data • Planned/Unplanned outage • Poor hardware performance • Improper device configurations

SPP runs a daily Correctness Report using GPA SIEGate. This report may also be run at the Member datacenter point of aggregation using GPA SIEGate or GPA PDQTracker. An example report is shown on the next page. ** SPP is also evaluating similar reports using EPG software.



9.2 Data Completeness Data Completeness refers to whether there are any gaps in the data, and if so, the size of the gaps. Primary causes of loss of completeness include:

• The PMU itself ceases to operate properly • Communication link issues between a properly operating PMU and the member datacenter

(latency, bandwidth limitations, communication device hardware failure) • Data aggregator issues at the Member datacenter and/or PMU location • Communication link issues between the Member datacenter and SPP (latency, bandwidth

limitations, communication device hardware failure) SPP runs a daily Completeness Report using GPA SIEGate. This report may also be run at the Member datacenter point of aggregation using GPA SIEGate or GPA PDQTracker. An example report is shown on the next page. ** SPP is also evaluating similar reports using EPG software.



10 Appendix

10.1.1 SPP EMS Model Area Names

Control Area Identifier Company Name

CSWS American Electric Power EDE Empire District Electric

GRDA Grand River Dam Authority INDN Independence Power and Light KACY Kansas City Board of Public Utilities KCPL Kansas City Power and Light LES Lincoln Electric System

MPS Missouri Public Service NPPD Nebraska Public Power District OKGE Oklahoma Gas and Electric OPPD Omaha Public Power District SECI Sunflower Electric Cooperative Inc. SPA Southwestern Power Administration

SPRM City Utilities of Springfield, Missouri SPS Southwestern Public Service Company

WAUE Western Area Power Administration - Upper Great Plains East WFEC Western Farmers Electric Cooperative

WR Westar Energy

SPP PMU Communications Handbook pmu communication... · 2019-02-08 · SPP PMU Communication...

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